1. Field of the Invention
The present invention generally relates to methods and apparatus for use in oil and gas wellbores. More particularly, the invention relates to using instrumentation to monitor downhole conditions within wellbores.
2. Description of the Related Art
In well completion operations, a wellbore is formed to access hydrocarbon-bearing formations by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill support member, commonly known as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annular area is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. A cementing operation may optionally be conducted in order to fill the annular area with cement and set the casing string within the wellbore. Using apparatus known in the art, the casing string may be cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole. The amount and extent of cement in the annular area may vary from a small amount of cement only at the lower portion of the annulus to a large amount of cement extending to the surface or the top of the casing string. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In this respect, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is removed. A first string of casing or conductor pipe is then run into the wellbore and set in the drilled out portion of the wellbore, and cement may be circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing, or liner, is run into the drilled out portion of the wellbore. The second string is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The second liner string is then fixed, or “hung” off of the existing casing by the use of slips which utilize slip members and cones to wedgingly fix the new string of liner in the wellbore. The second casing string may then be cemented. This process is typically repeated with additional casing strings until the well has been drilled to total depth. As more casing strings are set in the wellbore, the casing strings become progressively smaller in diameter in order to fit within the previous casing string. In this manner, wells are typically formed with two or more strings of casing of an ever-decreasing diameter.
As an alternative to the conventional method, drilling with casing is a method increasingly used to place casing strings of decreasing diameter within the wellbore. This method involves attaching a cutting structure in the form of a drill bit to the same string of casing which will line the wellbore. Rather than running a drill bit on a smaller diameter drill string, the drill bit or drill shoe is run in at the end of the larger diameter of casing that will remain in the wellbore and may be cemented therein. Drilling with casing is often the preferred method of well completion because only one run-in of the working string into the wellbore is necessary to form and line the wellbore.
While drilling the drill string or the casing string into the formation, drilling fluid is ordinarily circulated through the inner diameter of the casing string or drill string, out through the casing string or drill string and up around the outer diameter of the casing string or drill string. Typically, passages are formed through the drill bit to allow circulation of the drill fluid. Fluid circulation prevents collapse of the formation around the drill string or casing string, forces the cuttings produced by the drill bit drilling through the formation out from the wellbore and up to the surface rather than allowing the cuttings to enter the inner diameter of the drill string or casing string, and facilitates the drilling process by forming a path through the formation for the drill bit.
Recent developments have allowed sensing of parameters within the wellbore and within the formation during the life of a producing well. Typically, the drill string or casing string with the drill bit attached thereto is drilled into the formation to a depth. When drilling with the drill string, the drill string is removed, a casing string is placed within the drilled-out wellbore, and the casing string may be cemented into the wellbore. When drilling with casing, the casing string may be cemented into place once it has drilled to the desired depth within the formation. Production tubing is then inserted into the casing string, and perforations are placed through the production tubing, casing string, cement around the casing string, and the formation at the desired depth for production of hydrocarbons. The production tubing may have sensors therearound for sensing wellbore and formation parameters while drilling and during production operations.
Historically, monitoring systems have used electronic components to provide pressure, temperature, flow rate and water fraction on a real-time basis. These monitoring systems employ temperature gauges, pressure gauges, acoustic sensors, seismic sensors, electromagnetic sensors, and other instruments or “sondes,” including those which provide nuclear measurements, disposed within the wellbore. Such instruments are either battery operated, or are powered by electrical cables deployed from the surface. The monitoring systems have historically been configured to provide an electrical line that allows the measuring instruments, or sensors, to send measurements to the surface.
Recently, optical sensors have been developed which communicate readings from the wellbore to optical signal processing equipment located at the surface. Optical sensors may be disposed along the production tubing within a wellbore. An optical line or cable is run from the surface to the optical sensor downhole. The optical sensor may be a pressure gauge, temperature gauge, acoustic sensor, seismic sensor or other sonde. The optical line transmits optical signals to the optical signal processor at the surface.
The optical signal processing equipment includes an excitation light source. Excitation light may be provided by a broadband light source, such as a light emitting diode (LED) located within the optical signal processing equipment. The optical signal processing equipment also includes appropriate equipment for delivery of signal light to the sensor(s), e.g., Bragg gratings or lasers and couplers which split the signal light into more than one leg for delivery to more than one sensor. Additionally, the optical signal processing equipment includes appropriate optical signal analysis equipment for analyzing the return signals from the Bragg gratings.
The optical line is typically designed so as to deliver pulses or continuous signals of optic energy from the light source to the optical sensor(s). The optical cable is also often designed to withstand the high temperatures and pressures prevailing within a hydrocarbon wellbore. Preferably, the optical cable includes an internal optical fiber which is protected from mechanical and environmental damage by a surrounding capillary tube. The capillary tube is made of a high strength, rigid-walled, corrosion-resistant material, such as stainless steel. The tube is attached to the sensor by appropriate means, such as threads, a weld or other suitable method. The optical fiber contains a light guiding core which guides light along the fiber. The core preferably employs one or more Bragg gratings to act as a resonant cavity and to also interact with the sonde.
While optical sensors placed on production tubing allow measurements while the production tubing is located within the wellbore, the sensors on production tubing do not allow monitoring of wellbore and formation conditions during the drilling and well completion operations and after the production tubing is removed from the wellbore. Thus, the sensors are only deployed temporarily while the production tubing is within the wellbore. Furthermore, when employing seismic sensors which need to be coupled to the formation, sensors located on production tubing are located at a distance from the formation, so that measurements of formation parameters derive some inaccuracy due to signal attenuation of the sensor without coupling the sensor to the formation. Coupling the sensors to the formation requires complicated maneuvers and equipment across the distance between the production tubing and the formation.
Accordingly, there is a need for apparatus and methods for permanently deploying measurement devices. There is a need for apparatus and methods for measuring wellbore and formation conditions throughout drilling and well completion operations, well production operations, and the remaining operations of a well. Furthermore, there is a need for apparatus and methods for locating measurement devices closer to the formation than is currently possible to increase the accuracy of the measured parameters and to facilitate coupling of the optical sensors to the formation.